1. Field of Invention
The present invention relates broadly to treatment of wells and wellbores. In a preferred aspect, the invention relates to oil well drilling operations, particularly drill-in operations, and more particularly to novel drill-in fluids and methods of drilling involving the use of at least two different drilling fluids, one of which is a novel drill-in fluid.
2. Background Art
Drilling operations typically involve mounting a drill bit on the lower end of a drill pipe or "drill stem," which may then be rotated against the bottom of a hole to penetrate a formation and create a borehole. A drilling fluid, typically a drilling mud, may be circulated down through the drill pipe, out the drill bit, and back up to the surface through the annulus between the drill pipe and the borehole wall. The drilling fluid has a number of purposes, including cooling and lubricating the bit, carrying the cuttings from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole. Another type of fluid used in oil and gas wells, distinguishable from drilling fluids, is a "completion fluid," which herein refers to any fluid that is pumped down a well after drilling operations are completed, and will refer broadly to fluids introduced during acidizing, perforating, fracturing or workover operations. In a preferred aspect, the present invention is directed to drilling fluids.
In one aspect the present invention relates to a specific type of drilling fluid, namely a "drill-in" fluid, which is pumped through the drill pipe while drilling through the "payzone," which refers to the part of the underground formation or reservoir of an oil or gas well that is believed to hold the oil or gas to be removed, i.e., the "producing" part of the formation. In another aspect, the invention relates to a method for drilling an oil or gas well requiring the use of at least two different types of drilling fluids, one for the initial surface formations, the other through the payzone. When the lower end of the drill pipe enters the payzone, it is often desirable to protect the formation from damage and fluid loss.
Many drilling fluids are unacceptable as drill-in fluids. For example, many drilling fluids have relatively high viscosities at high shear rates, which makes them undesirable due to the mechanical constraints they often place upon the drilling equipment and damage to the reservoir itself. A fluid with high viscosities at high shear rates often tends to require high pump pressures which may exceed the capabilities of the system pumping the fluid, e.g., the pump system on the drilling rig. One solution might be to reduce the pump rate to accommodate the constraints on the equipment and reservoir. But reduction in pump rate generally requires a corresponding reduction in drilling rate, which can significantly increase the overall cost of drilling a well. Another solution might be to provide pumps with higher pumping capabilities. But in addition to cost and damage, higher pump pressures may result in breakdown of the formation.
Higher viscosities tend to result in higher pressures exerted outward on the borehole, which may result in mechanical damage to the formation, thus reducing the ability of a well to produce oil or gas. This may be particularly true with slimhole drilling operations, where small diameter pipe is used to pump fluids through the hole at high pressures. Higher viscosity fluids may result in inadvertent fracturing of the formation, which may create a need to stop drilling operations to seal the fracture. Further, the fracture damage may be so severe that the well is permanently unable to produce oil or gas.
Examples of fluids that are unacceptable for use as drill-in fluids are shown in U.S. Pat. No. 4,822,500. There, well treating fluids were prepared using single salt brines, namely saturated sodium chloride brine systems. The densities of those fluids were too low for use in high pressure formations. Moreover, increasing the densities of those fluids also increased plastic viscosities to unacceptable levels. As indicated in Table IV of that patent, the lower plastic viscosities tended to be obtained only at densities less than 1.50 g/cm.sup.3. A fluid having a density of 1.50 g/cm.sup.3 in Table IV was reported to have an extremely high plastic viscosity of 60 lb/ft.sup.2, which the present inventor considers unacceptable for use in the payzone, i.e., as a drill-in fluid, because it might tend to cause inadvertent fracturing. Another problem with the drilling fluids reported in that patent is the need to add solid weighting agents to the base brine to increase its density above 1.2 g/cm.sup.3. The addition of such weighting agents tends to cause increase in filter cake formation and plastic viscosity, making it less desirable as a drill-in fluid.
Use of divalent salts may also present problems in drilling fluids, particularly in drilling fluids. For example, polymers commonly used as suspending agents, particularly polymers belonging to the genus xanthamonas gum (xanthan gum) are intolerant of divalent salts, and tend to form precipitates and other undesirable solid byproducts. Those polymers do not hydrate properly with the divalent salts and accordingly may not impart the desired viscosity to the base brine. Other polymers, such as hydroxyethyl cellulose (HEC), often incorporated in completion fluids, do not provide the desired suspension qualities to the fluid. Still others may react with the base brine to create solids or other undesirable byproducts.
Accordingly, there exists a continuing need for a high density well treatment fluid that would be useful as a drill-in fluid and would overcome one or more of the identified shortcomings.